This invention is generally applicable to cutting earthen or subterranean formations. More particularly, this invention is applicable to drilling wells such as oil, gas or geothermal wells. Additionally, this invention may be used in drilling and mining wherein tunnels, pipe chases, foundation piers, holes or other penetrations or excavations are made through formations for purposes other than production of hydrocarbons or geothermal energy.
The process of drilling a well bore or cutting a formation to construct a tunnel and other subterranean earthen excavations is a very interdependent process that preferably integrates and considers many variables to ensure a usable bore is constructed. As is commonly known in the art, many variables have an interactive and cumulative effect of increasing drilling costs. These variables may include formation hardness, abrasiveness, pore pressures and formation elastic properties. In drilling wellbores, formation hardness and a corresponding degree of drilling difficulty may increase exponentially as a function of increasing depth. A high percentage of the costs to drill a well are derived from interdependent operations that are time sensitive, i.e., the longer it takes to penetrate the formation being drilled, the more it costs. One of the most important factors affecting the cost of drilling a well bore is the rate at which the formation can be penetrated by the drill bit, which typically decreases with harder and tougher formation materials and formation depth. Consequently, drilling costs typically tend to increase exponentially with depth.
There have been many substantially varied efforts to meaningfully increase the effective rate of penetration (xe2x80x9cROPxe2x80x9d) during the drilling process and to thereby reduce the cost of drilling or cutting formations by improving drill bit efficiency. Dr. William C. Maurer""s book entitled, xe2x80x9cAdvanced Drilling Techniquesxe2x80x9d published by Petroleum Publishing Company in 1980 outlines several novel efforts in an attempt to address the issue of increasing the rate of penetration. Further, Dr. Maurer""s book illustrates the tremendous interest, breadth of participation and significant money spent attempting to fulfill the long-felt need for substantially improving the ROP.
Three significant efforts of a sustained nature to meaningfully increase ROPs warrant discussion relating to this invention. The first two of these efforts involved high-pressure circulation of a drilling fluid as a foundation for potentially increasing the rate of penetration. It is common knowledge that hydraulic power available at the rig site vastly outweighs the power available to be employed mechanically at the drill bit. For example, modern drilling rigs capable of drilling a deep well typically have in excess of 3000 hydraulic horsepower available and can have in excess of 6000 hydraulic horsepower available while less than one-tenth of that hydraulic horsepower may be available at the drill bit. Mechanically, there may be less than 100 horsepower available at the bit/rock interface with which to mechanically drill the formation.
One of the first significant efforts at increasing rates of penetration was a promising attempt to directly harness and effectively utilize hydraulic horsepower at the drill bit by incorporating entrained abrasives in conjunction with high pressure drilling fluid (xe2x80x9cmudxe2x80x9d). This resulted in an abrasive laden, high velocity jet assisted drilling process. The most comprehensive work conducted in attempting to use drilling fluid entrained abrasives was conducted by Gulf Research and Development Company. This work is described in detail in a number of published articles and is the subject of many issued patents. This body of work teaches the use of abrasive laden jet streams to cut concentric grooves in the bottom of the hole leaving concentric ridges that are then broken by the mechanical contact of the drill bit. There was ample demonstration that the use of entrained abrasives in conjunction with high drilling fluid pressures caused accelerated erosion of surface equipment and an inability to control drilling mud density, among other issues. Generally, the use of entrained abrasives was considered practically and economically unfeasible. This work was summarized in the last published article titled xe2x80x9cDevelopment of High Pressure Abrasive-Jet Drilling,xe2x80x9d authored by John C. Fair, Gulf Research and Development. It was published in the Journal of Petroleum Technology in the May 1981 issue, pages 1379 to 1388. Due to this discouraging terminal report, the industry has not meaningfully attempted to further investigate and develop a system to use abrasives for well bore drilling purposes.
A second significant effort to directly harness and effectively utilize the hydraulic horsepower available at the bit incorporated the use of ultra-high pressure jet assisted drilling. A group known as FlowDril Corporation was formed to develop an ultra-high-pressure liquid jet drilling system in an attempt to significantly increase the rate of penetration. FlowDril spent large sums of money attempting to commercially field a drilling system. The work was based upon U.S. Pat. No. 4,624,327 and is well documented in the published article titled xe2x80x9cLaboratory and Field testing of an Ultra-High Pressure, Jet-Assisted Drilling Systemxe2x80x9d authored by J. J. Kolle, Quest Integrated Inc., and R. Otta and D. L. Stang, FlowDril Corporation; published by SPE/IADC Drilling Conference publications paper number 22000. Further to the cited publication, it is common knowledge that the complications of pumping and delivering ultra-high-pressure fluid from surface pumping equipment to the drill bit proved both operationally and economically unfeasible. FlowDril Corporation is continuing development of an xe2x80x9cUltra-High Pressure Down Hole Intensifierxe2x80x9d as a substitute technology in an effort to commercialize its product. Of note is the fact that FlowDril demonstrated that generating a kerf near the hole gage will produce increased efficiencies for the mechanical action of the drill bit. This is cited in the conclusions stated in the article titled xe2x80x9cUltra-High Pressure Jet Assist of Mechanical Drillingxe2x80x9d authored by S. D. Veehuizen, FlowDril Corp; J. J. Kolle, Hydropulse L. L. C.; and C. C. Rice and T. A. O""Hanlon, FlowDril Corp. published by SPE/IADC Drilling Conference publications, paper 37579.
A third significant effort at increasing rates of penetration by taking advantage of hydraulic horsepower available at the bit was developed by the inventor who was issued U.S. Pat. No. 5,862,871 for the process. This development employed the use of a specialized nozzle to excite normally pressured drilling mud at the drill bit. The purpose of this nozzle system was to develop local pressure fluctuations and a high speed, dual jet form of hydraulic jet streams to more effectively scavenge and clean both the drill bit and the formation being drilled. It is believed that these novel hydraulic jets were able to penetrate the fracture plane generated by the mechanical action of the drill bit in a much more effective manner than conventional jet were able to do. Rate of penetration increases from 50% to 400% were field demonstrated and documented in the field reports titled xe2x80x9cDualJet Nozzle Field Test Reportxe2x80x94Security DBS/Swift Energy Company,xe2x80x9d and xe2x80x9cDualJet Nozzle Equipped M-1LRG Drill Bit Runxe2x80x9d. The ability of the dual jet (xe2x80x9cDualJetxe2x80x9d) nozzle system to enhance the effectiveness of the drill bit action to increase the effective rate of penetration required that the drill bits first initiate formation indentations, fractures, or both. These features could then be exploited by the hydraulic action of the DualJet nozzle system.
Due at least partially to the effects of overburden pressure, formations at deeper depths may be inherently tougher to drill due to changes in formation pressures and rock properties, including hardness and abrasiveness. Associated in-situ forces, rock properties and increased drilling fluid density effects may set up a threshold point at which the drill bit drilling mechanics changes from formation fracture inception to a work hardening effect upon the formation. Generated by indentation mechanics upon more plastic rocks such as typically found at deeper depths, the work hardening effects may cause flaking failure of the drilled formation surface by the drill bit, as opposed to fracture inception. Repeated compacting of the formation by the drill bit teeth may toughen the plastic-like formation encountered at deeper depths. The effectiveness of the DualJet nozzle system in increasing rate of penetration in these toughened, more plastic formations was reduced due to a reduction in the generation of fractures and chip-like cuttings. Under these tougher drilling conditions, the process of chip generation was solely the function of the mechanical action of the drill bit, resulting in reduced rate of penetration. If the mechanical action of the drill bit could no longer incipiate formation fractures under these conditions, it became obvious that a hydraulic assist technology, which was thereby unable to effectively cut the formation, would be of little assistance.
Another significant factor adversely effecting rate of penetration in formation drilling, especially in plastic type rock drilling, such as shales, is a build-up of hydraulically isolated crushed rock material on the surface being drilled. This occurrence is predominantly a result of repeated impacting and recompacting of previously drilled particulate material on the bottom of the hole by the bit teeth, thereby forming a false bottom under the repeated impacting of the drill bit teeth. The substantially continuous process of drilling, recompacting, removing, re-depositing and recompacting and drilling new material may significantly adversely effect drill bit efficiency and rate of penetration. The recompacted material is at least partially removed by mechanical displacement due to the cone skew of the roller cone type drill bit and partially removed by hydraulics, again emphasizing the importance of good hydraulic action and hydraulic horsepower at the bit. For hard rock bits, build-up removal by cone skew is typically reduced to near zero, which may make build-up removal substantially a function of hydraulics.
The history of attempts to increase the rate of penetration as the well bore deepens illustrates a fundamental problem. This problem has been the inability to employ a means to generate formation fractures or formation disintegration under in-situ conditions at depth. There are no modern processes or practices currently available to the drilling industry that can drill at relatively high rates of penetration under xe2x80x9cat depthxe2x80x9d conditions. Therefore, there is a high demand for a drilling system capable of commercially drilling well bores at high rates of penetration in deep or tough formations.
There have been many efforts to increase ROP by improving the mechanical and the hydraulic actions of the drill bit. When a drill bit cuts rock or formation, several actions effecting rate of penetration and bit efficiency may be occurring. The bit teeth may be cutting, milling, pulverizing, scraping, shearing, sliding over, indenting and fracturing the formation the bit is encountering. The desired result is that formation cuttings or chips are generated and circulated to the surface by the drilling fluid. Other factors may also effect rate of penetration, including formation structural or rock properties, pore pressure, temperature and drilling fluid density may also adversely effect rates of penetration.
There are generally two categories of modern drill bits that have evolved from over a hundred years of development and untold amounts of dollars spent on the research, testing and iterative development. These are the commonly known fixed cutter drill bit and the roller cone drill bit. Within these two primary categories, there are a wide variety of variations, with each variation designed to drill a formation having a general range of formation properties.
The fixed cutter drill bit is generally employed to drill the relatively young and unconsolidated formations while the roller cone type drill bit is generally employed to drill the older more consolidated formations. These two categories of drill bits generally constitute the bulk of the drill bits employed to drill oil and gas wells around the world. When a typical roller cone rock bit tooth presses upon a very hard, dense, deep formation, the tooth point may only penetrate into the rock a very small distance, while also at least partially, plastically xe2x80x9cworkingxe2x80x9d the rock surface. Under conventional drilling techniques, such working the rock surface may result in toughening the formation in such a way as to make it even more difficult to penetrate with a drill bit. This peening effect may equalize the compressive forces over the drilling surface, creating a toughened xe2x80x9cskinxe2x80x9d or xe2x80x9chard-facexe2x80x9d on the formation.
With roller cone type drilling bits, a relationship exists between the WOB, the number of teeth that impact upon the formation, and the drilling RPM. This relationship may be roughly equivalent to a xe2x80x9cshots per secondxe2x80x9d factor in shot peening metals to alter the properties of the metal surface. Since WOB may be relatively constant, the repeated pulsing action of the teeth upon the formation can cause work hardening of the formation and may thereby impede penetration by the rock bit into the formation. This effect may become more pronounced as formation depth, rock hardness and overburden forces increase.
Subsequent increases in WOB may assist the rate of penetration, but may also result in accelerated bit bearing wear, breakage of bit teeth, or both. Unanticipated changes in formation properties and formation drillability over the course of the well bore may result in a mismatch or less than ideal mix between bit type being used, controllable drilling parameters and formations actually encountered. Severe mismatches may result in accelerated bit wear, destruction, or both. Anticipation of such occurrences may result in the drilling operator operating the bit in a rather conservative mode to prevent damage to the bit and to avoid frequent bit replacements. Such replacements require additional time and equipment, resulting in increased well bore expenses.
The oil and gas exploration and production industry is projected to spend in excess of $100 billion dollars in the current FY2000 according to Arthur Anderson""sxe2x80x94xe2x80x9cGlobal E7P Trendsxe2x80x9d July 1999. As demonstrated, and from common knowledge within the oil and gas exploration and production industry, improvement in the rate of penetration in the drilling of a well bore can have a significant economic effect.
An improved method for cutting or drilling subterranean formations is desired in order to reduce well or excavation costs through increased rates of penetration, reduced bit wear and reduced drilling time. It is also desired to increase the efficient use of hydraulic and mechanical energy at a drill bit in drilling or cutting such formations. The disadvantages of the prior art are substantially overcome by the present invention, and an improved method and system for cutting or drilling through subterranean formations are hereinafter disclosed. This invention has particular utility in drilling well bores, cutting tunnels, pipe chases and other subterranean formation excavations.
A suitable method for drilling or cutting a subterranean formation according to the present invention includes concurrently engaging impactors with the formation being drilled while rotating a drill bit. In an exemplary application, a majority of the impactors may be substantially spherical steel shot having a mean diameter of from 0.150 to 0.250 inches. The impactors may be of sufficient mass and may be accelerated to sufficient velocity through a nozzle with which to impale into and/or engage the impactors with a formation and thereby effect substantial structural changes to the engaged formation. The anticipated formation changes to the formation matrix or structure are well beyond the changes that were possible with mere abrasives and/or high pressure fluids. The impactors of this invention substantially have a higher mass and size than prior abrasive or jetting particles, however, they are accelerated substantially to a velocity lower than the velocities used in abrasive or jetting technology. The impactors of this invention may be a plurality of independent, solid material, impactor bodies with a majority by weight of the impactors having a mean outer diameter of at least 0.100 inches.
Impacting a formation with a relatively large impactor while drilling may beneficially alter the structural properties of the formation to a depth not possible under prior art, so as to enhance the rate of penetration by the drill bit, through a number of combinations of both independent and inter-related mechanisms. These mechanisms include each of mechanical, thermal and hydraulic mechanisms, as discussed in the specification. Energy imparted into the formation ahead of the bit by the impactors may independently remove cuttings and formation, and may simultaneously and beneficially alter formation rock properties. The modified or altered formation may be more amenable to mechanical and/or hydraulic removal or cutting generation by rotational and gravitational energy in the bit teeth.
Such altered formation may also be more amenable to removal by the kinetic energy in subsequent impactor and in the cutting fluid. In addition, the effect of the impactors upon the formation may enhance expenditure of hydraulic energy at the formation face to hydraulically create and remove cuttings from the formation face. Impact from the impactor upon the formation may mechanically induce a plurality of micro-fractures, stress fractures or other formation deformations in the impacted area, which may then be more readily hydraulically exploited. Such enhanced hydraulic action and mechanical deformations may reduce the work required by the bit teeth to both create and remove the formation cuttings, thereby extending bit life while increasing the rate of penetration.
Under prior art, the use of abrasive particles entrained within drilling fluid in drilling operations has been to relieve relatively small particles from the drilled surface. Under such operations, the relieved formation particles typically have a mass or size substantially equal or less than the mass or size of the abrasive particle. This disclosure is related to the use of relatively larger impactors with the significance event mechanism being formation deformation, fracturing, structural alteration or propagation therein by the impactor. Such events may result in or create mechanical advantages, force point location changes, overburden stress relief in localized areas and dynamic mixing with the formation. One impactor may remove several hundred rock grains or particles. An additional benefit may be to cause a fundamental shift in the understanding and application of rock drilling mechanics, theories, and techniques.
It is significant in this invention that a substantial portion of the mechanical advantages are obtained by impact mechanics as opposed to the abrasive mechanics of prior art. Impactors entrained within a drilling fluid are accelerated through one or more nozzles in or near the bit. Although generally accelerated to a lower velocity than prior art abrasives, due to their higher mass and larger size, a substantial portion by weight of the impactors may impact the formation ahead of the bit consistently with sufficient energy to structurally alter and/or at least partially penetrate into the formation, to a depth beyond the first two layers of encountered formation grain material or particles. In many instances, the impactors will be impacted into the formation to a depth several times the diameter of the impactor. Such technique is significantly distinguishable from the abrasive and high-pressure hydraulic methods of the prior art in that under prior art the formation was not deformed beyond the first layer of formation grain material or particles. The impactors may act independent from the cutting and compressing action of the bit, and the impactors may act in concert with the mechanical, cutting and compressing actions of the bit to further enhance rate of penetration.
An impactor based drilling system for drilling well bores may be performed using substantially conventional drilling equipment as known and used in drilling well bores. A drilling rig including a fluid pump may pump a drilling fluid down a drill string from the drilling rig to a drill bit. The drilling fluid may be pumped by a fluid pump, through the drill string and through one or more bit nozzles as the bit is rotated while in engagement with the formation. The drilling fluid and cuttings may be circulated substantially back to the surface where the drilling fluid may be separated from the cuttings, such that the drilling fluid may be recirculated in the well bore. Additional known equipment may also be provided, including an impactor pump, such as a progressive cavity pump, to pump a slurry including impactors into the drilling fluid stream.
The impactors are geometrically larger than particulate material used for drilling or formation cutting under prior art, such as abrasives. In a preferred embodiment, the impactors are substantially spherical steel shot or BBs, having a mean diameter of at least 0.100 inches. The impactors are typically pumped at conventionally low drilling fluid circulation pressures and typically exit the bit nozzle such that a majority by weight of the impactors exiting the nozzle may impact the formation at a velocity less than 750 feet per second. The momentum of the impactors provides sufficient energy at the formation face, even at the relatively low velocity, to effect the desired formation structural distortion, alteration, penetration and/or fracturing. A plurality of individual impactors may be introduced into the fluid system and subsequently engaged with the formation substantially sequentially and continuously with respect to the other impactors introduced into the system.
The plurality of solid material impactors may be introduced into the cutting or drilling fluid to circulate the impactors with the fluid, through the cutting or drill bit and into engagement with the formation.
A cutting fluid or drilling fluid may be pumped at a pressure level and a flow rate level sufficient to satisfy an impactor mass-velocity relationship wherein a substantial portion by weight of the impactors may create a structurally altered zone in the formation. A substantial portion means at least five percent by weight of the impactors, and more particularly at least twenty-five percent by weight, and even more particularly, at least a majority by weight of the plurality of solid material impactors introduced into the drilling fluid. The structurally altered zone may have a structurally altered zone height in a direction perpendicular to a plane of impaction at least two times a mean particle diameter of particles in the formation impacted by the plurality of solid material impactors.
It is an object of the present invention to provide an improved system and method for cutting a formation, such as when drilling a well bore. The techniques of this invention may facilitate drilling well bores or cutting earthen formations in a commercially improved manner.
It is also an object of this invention to provide a method for drilling or cutting through formations with improved bit efficiency and rates of penetration. This invention may provide techniques which may significantly improve bit efficiency and rates of penetration. Such improvements may be realized through formation alteration, mechanical effects from both the impactors and the bit, and from improved use of hydraulic power at the bit.
It is further an object of this invention to provide improved methods of cutting or drilling through formations possessing a variety of formation properties. The methods and systems of this invention may be effectively applied to relatively soft formations as well as relatively hard or conventionally difficult to drill formations.
A further object of this invention is to provide improved methods and systems for cutting or drilling through formations in a variety of applications. The methods and systems of this invention may be applied to the drilling of well bore, such as used in oil and gas drilling, and geothermal drilling. In addition, the methods and systems of this invention may be effectively applied to mining, tunneling, cutting pipe chases, trenches, foundation piers and other earthen excavation operations.
It is also an object of this invention to provide methods and systems for supplementing the mechanical action of the bit with a fluid based impactor delivery system with sufficient energy to satisfy a mass-velocity relationship sufficient to supplement and/or assist the mechanical action of the bit.
It is an additional object of this invention to provide methods and systems for introducing solid material impactors into a drilling fluid to impart energy generated in the impactors into the formation generally ahead of the drill bit. The impactors utilized by this invention are relatively large as compared to abrasive type particles. The introduction of impactors into the drilling fluid and subsequently increasing the velocity of the impactors while passing through a nozzle can sufficiently energize the impactors to alter the structural properties of the formation matrix. Such altered matrix may subsequently be exploited mechanically and hydraulically by the drill bit. The impactors may also effect removal of multiple grains or chips of formation as a direct result of the impact event.
It is a feature of this invention that the invention may utilize impactors having a mean diameter or length dimension of at least 0.100 inches. In a preferred embodiment, a majority by weight of the impactors may include a mean diameter between 0.150 inches and 0.250 inches. Other embodiments may utilize even larger impactors.
It is also a feature that the impactors may be at least partially energized through either a convention bit nozzle or through other known non-convention nozzles, such as a dual jet nozzle. Special nozzles may also be designed to accommodate or energize the impactors.
It is a further feature of this invention that the impactors may be generally spherically shaped, crystalline shaped, including angular and sub-angular shaped, or specially shaped. The impactors may also be metallic, such as steel, thereby having a relatively high density and high compressive strength. Alternatively, other materials may be utilized which may possess desirable properties as appropriate to the application at hand. For example, a particular application may be best optimize by an impactor possessing a relatively high surface area to weight ratio, or low density with high crush resistance.
It is a feature of this invention that the required energy levels in the impactors may be achieved by relatively low impactor velocities at the point of impact. Impactor velocities at the point of impact may typically be less than 750 feet per second for impactors each having a mean diameter in excess of 0.100 inches.
Yet another feature of the invention that the impactors may create a structurally altered zone or matrix in the formation having an altered length, height, width, or any combination thereof, of at least two times a mean particle diameter of particles in the formation impacted by the impactor. The alteration may be due to the impactor impact, the interaction of the bit with the respective impactor, the interaction of multiple impactors, or any combination thereof.
Another significant feature of this invention is that the impactors may facilitate leveraging the rotational and gravitational forces of the bit to act angularly or laterally within the formation being drilled or cut, to effect cutting generation.
It is a feature of this invention that the rate of impactor introduction into the drilling fluid may be altered as desired, or as determined from drilling parameters or formation characteristics. For example, when drilling a well bore, relatively fewer impactors may be desired when drilling a hard formation as compared to the number of impactors desired when drilling a relatively gummy formation.
It is also a feature of this invention that the methods and systems of this invention may be applied to many subterranean excavation, cutting and/or drilling operations. Applicable operations may include drilling a well bore in the oil and gas industry, geothermal wells, tunnels, pipe chases, foundation piers, or other earthen penetrations.
It is an advantage of this invention that the invention may generally utilize existing drilling rig equipment. Additional known equipment may be included, such as an impactor source vessel, impactor mixing vessel, an impactor slurry pump and line, and an impactor introduction port. For example, the introduction port may be a port on the gooseneck above a rotary swivel.
It is also an advantage of the invention that very little additional training or skill may be required of the crews operating the drilling rig. Some experience and skill may otherwise be useful in adjusting the impactor introduction rate. However, even impactor rate adjustment may not require much more skill than other related drilling decisions, such as weight on bit, rotary speed, pump rate and pump pressure. Such determinations are regularly made during drilling and cutting operations.
Yet another advantage of this invention is that it may be practiced utilizing equipment that is known in the drilling and formation cutting industries. Although some known equipment may be adapted that would not otherwise have been adapted for use with this invention, the invention does rely upon novel equipment for an operation embodiment. For example, a progressive cavity pump may pump the impactor slurry and a drill bit may utilize a standard size set of bit nozzles.
Still a further advantage of the invention that the footage drilled by a given drill bit may be significantly increased and that bit life may be extended by reducing the amount of work per unit time and work per unit distance that the bit must perform. Such advantages may also reduce rig time by reducing the number of bit trips required to change drill bits.
A significant advantage of this invention is that the additional costs for including this invention in a drilling or cutting operation may be relatively nominal as compared to the total drilling costs. In addition, the additional costs may be significantly offset by the increased rates of penetration and decreased rig time.
The methods and systems described herein are not limited to specific impactor sizes or shapes but rather controlled by the physical and material sciences of force, velocity, melting points, rock properties, mechanics, hydraulics, compressive and fracture characteristics, porosity, etc. This invention may be applied broadly and to other fields of endeavor where the cutting of earthen formations or other materials, such as concrete, by impact mechanics rather than abrasion is important. These and further objects, features, and advantages of the present invention will become apparent from the following detailed description, wherein reference is made to figures in the accompanying drawings.